Method and system for extracting reservoir fluid sample

ABSTRACT

Methods and systems for the extraction of a formation fluid sample using a fluid extraction tool including an elongated body and a sealing pad extending therefrom, the sealing pad having an opening for establishing fluidic communication between an earth formation and the elongated body. The sealing pad communicable with from a container holding a selective permeability agent (SPA) capable of modifying the permeability of one or more fluids within the formation. The container coupled with a device for injecting the SPA into the earth formation and extracting a formation fluid sample therefrom.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a national stage entry of PCT/US2016/056288 filedOct. 10, 2016, said application is expressly incorporated herein in itsentirety.

FIELD

The present disclosure relates generally to methods of retrieving andprocessing reservoir fluid samples. In particular, the subject matterherein generally relates to methods of extracting enhanced formationfluid samples.

BACKGROUND

Wellbores are drilled into the earth for a variety of purposes includingtapping into hydrocarbon bearing formations to extract the hydrocarbonsfor use as fuel, lubricants, chemical production, and other purposes.The oil and gas industry typically conducts comprehensive evaluations ofunderground hydrocarbon reservoirs prior to wellbore development andproduction. Formation evaluation procedures generally involve thecollection of formation fluid samples for hydrocarbon content analysis,an estimation of the formation permeability and directional uniformity,a determination of the formation fluid pressure, and various otheranalyses. Measurements of such parameters are typically performed usingdevices including, but not limited to, downhole formation testing tools.

Characteristics of the hydrocarbons within an earth formation can bedetermined using a formation mobility test performed in a downholeformation testing tool. Formation mobility is defined as permeability(k) divided by fluid viscosity (μ). The governing equation of theorifice flow problem for mobility calculation is based on Darcy'sequation, with the consideration of the geometry of the orifice openingof the downhole formation testing tool. The mobility calculation fromformation tester measurements is well defined in a single fluid phasesaturated porous rock regime. However, for multiphase flow the formationfluid mobility provides only an overall mobility which does notdistinguish mobility of one fluid phase from another. Furthermore, fluidflow in fractured reservoir is dominated by the flow through fractures,the mobility of rock matrix is not easily determined.

To obtain a reservoir fluid sample for testing, a fluid extraction toolcan be used to extract fluids from the formation at a desired depth.Extraction of a formation fluid can be a long and tedious process due tothe need to pump out unwanted mud filtrates in order to obtain a clean,uncontaminated sample. Prolonged pumping processes are not uncommon, andobtaining a high quality sample is not guaranteed, especially in certainreservoir types. For example, samples obtained from depths located intransition zones, high-water-cut reservoirs, and fractured reservoirs,where the fractures are connected to water-bearing layers, the samplecan show high water-contamination despite a prolonged pumping time.

Relative permeability modifiers have been used to reduce waterproduction in high-water cut reservoirs, to maximize recovery frommature fields, and to reduce capillary pressure and enable rapid onsetof gas production from tight earth formations. These agents reduce theeffective permeability of water, without significantly affecting gas oroil permeability.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the present technology will now be described, by wayof example only, with reference to the attached figures, wherein:

FIG. 1 is a diagram of a wellbore operating environment in which anapparatus, method, and system, having a fluid extraction tool, may bedeployed, according to an exemplary embodiment;

FIG. 2 is a diagram of a modular fluid extraction tool having aformation tester, according to an exemplary embodiment;

FIG. 3A is a diagram of a formation tester module, according to anexemplary embodiment;

FIG. 3B is a front view of the sealing pad of a formation tester,according to an exemplary embodiment;

FIG. 4A is an illustration depicting a conventional system bus computingsystem architecture, according to an exemplary embodiment;

FIG. 4B is an illustration depicting a computer system having a chipsetarchitecture, according to an exemplary embodiment; and

FIG. 5 is a flowchart showing a method for extracting formation fluidsamples.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration,where appropriate, reference numerals have been repeated among thedifferent figures to indicate corresponding or analogous elements. Inaddition, numerous specific details are set forth in order to provide athorough understanding of the embodiments described herein. However, itwill be understood by those of ordinary skill in the art that theembodiments described herein can be practiced without these specificdetails. In other instances, methods, procedures and components have notbeen described in detail so as not to obscure the related relevantfeature being described. Also, the description is not to be consideredas limiting the scope of the embodiments described herein. The drawingsare not necessarily to scale and the proportions of certain parts havebeen exaggerated to better illustrate details and features of thepresent disclosure.

In the above description, reference to up or down is made for purposesof description with “up,” “upper,” “upward,” or “uphole” meaning towardthe surface of the wellbore and with “down,” “lower,” “downward,” or“downhole” meaning toward the terminal end of the well, regardless ofthe wellbore orientation. Correspondingly, the transverse, axial,lateral, longitudinal, radial, etc., orientations shall meanorientations relative to the orientation of the wellbore or tool. Theterm “axially” means substantially along a direction of the axis of theobject. If not specified, the term axially is such that it refers to thelonger axis of the object.

Several definitions that apply throughout the above disclosure will nowbe presented. The term “coupled” is defined as connected, whetherdirectly or indirectly through intervening components, and is notnecessarily limited to physical connections. The connection can be suchthat the objects are permanently connected or releasably connected. Theterm “outside,” “outer,” or “external” refers to a region that is beyondthe outermost confines of a physical object. The term “inside,” “inner,”or “internal” refers to a region that is within the outermost confinesof a physical object. The terms “comprising,” “including” and “having”are used interchangeably in this disclosure. The terms “comprising,”“including” and “having” mean to include, but not necessarily be limitedto the things so described.

Disclosed herein is a method for extracting samples of formation fluidat a predetermined depth. This is conducted by lowering a fluidextraction tool into a wellbore and injecting a selective permeabilityagent (SPA) into the formation. The SPA may include various agents suchas relative permeability modifiers (RPMs) to prevent the flow of waterand enhance the flow of hydrocarbons. After injecting the SPA into theformation, the fluid extraction tool can extract a sample of formationfluid from the earth formation, analyze the sample to determine themobility for the formation fluid and/or collect the sample inside thefluid extraction tool. The fluid extraction tool may be coupled with aprocessor for carrying out the aforementioned steps and/or fordetermining mobility of hydrocarbons within the formation.

The apparatus, method and system disclosed herein can selectively reducethe water-relative permeability in-situ in order to increase theprobability of obtaining a high quality, low-water-content sample in ashorter pumping time. In particular, the above allows for extraction of“cleaner” less contaminated formation hydrocarbon samples from thewellbore, more efficient extraction of such fluids and furthermore,determination of mobility of the hydrocarbon fluid phase in theformation.

FIG. 1 illustrates a system 100 according to various embodiments of thepresent disclosure. The fluid extraction tool 150 can be used as part ofa wireline logging operation, or as part of a downhole drillingoperation. For example, FIG. 1 shows a well during wireline loggingoperations. A drilling platform 120 may be equipped with a derrick 125that supports a hoist 115. Drilling oil and gas wells can be carried outusing a string of drill pipes connected together so as to form adrilling string that is lowered through a rotary table 110 into awellbore 140, also referred to herein as borehole 140.

Here it is assumed that the drilling string has been temporarily removedfrom the wellbore 140 to allow a fluid extraction tool 150 to be loweredby conveyance 130 into the wellbore 140. The conveyance 130 can includeany downhole conveyance such as wire, cable, e-line, slickline, braidedline, metallic wire, non-metallic wire, or composite wire, single ormultiple strands, as well as tubing, coiled tubing, joint tubing, pipe,or other tubular, combinations thereof, and the like. The fluidextraction tool 150 can be lowered to a desired location and stabilizedwithin the wellbore 140. As the fluid extraction tool 150 is stabilized,instruments included in the fluid extraction tool 150 (e.g., a formationtester) may be used to perform measurements on formation fluid suspendedwithin the earth formations 180 adjacent to the wellbore 140. Theformation fluid data can be analyzed either within the fluid extractiontool 150 or transmitted to a logging facility 170 on the surface forstorage, processing, and analysis. The logging facility 170 can beprovided with electronic equipment for various types of fluid analysis.For example, the logging facility 170 may include one or more surfacecomputers 172 and one or more displays 174. In the alternative, the datacan be transmitted and processed off-site.

Although FIG. 1 depicts a vertical wellbore 140, the present disclosureis equally well-suited for use in wellbores having other orientationsincluding horizontal wellbores, slanted wellbores, multilateralwellbores, or the like. It should be noted that while FIG. 1 generallydepicts a land-based operation, those skilled in the art would readilyrecognize that the principles described herein are equally applicable tooperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of this disclosure.

A variety of apparatuses and systems may be used to implement theactivities described above. The system may be used with a modulardownhole formation testing tool, including, but not limited to, theReservoir Description Tool (RDT®) by Halliburton, the Modular FormationDynamics Tester (MDT) by Schlumberger, or the Reservoir CharacterizationInstrument (RCI®) by Baker Hughes. As modified in accordance with thepresent disclosure, the tool is made suitable for testing, retrieval andsampling along sections of the earth formations by means of contact withthe surface of a wellbore. In accordance with an exemplary embodimentillustrated in FIG. 2 the fluid extraction tool 150 may have anelongated body comprising several modules (sections) capable ofperforming various functions. As shown in FIG. 2, the fluid extractiontool 150 may include an injection device 10, a power module 20, forexample, a hydraulic power module capable of converting electrical intohydraulic power; a formation tester 30 to take samples of the formationfluids; a flow control module 40 regulating the flow of various fluidsin and out of the tool; a fluid test module 50 for performing differenttests on a fluid sample; a multi-chamber sample collection module 60that may contain various size chambers for storage of the collectedfluid samples; a telemetry module 70 that provides electrical and datacommunication between the modules; and an uphole control unit (notshown) and other sections, designated in FIG. 2 collectively as 80. Oneof skill in the art would readily recognize that the various modules canbe rearranged depending on the specific applications, and that thearrangement herein should not be considered as limiting.

More specifically, the power telemetry section 70 conditions power forthe remaining tool sections. Each section can have its ownprocess-control system and can function independently. While section 70provides a common intra-tool power bus, the entire tool string(extensions beyond fluid extraction tool 150 not shown) shares a commoncommunication bus that is compatible with other logging tools. Thisarrangement enables the tool in a preferred embodiment to be combinedwith other logging systems, including, but not limited to, a MagneticResonance Image Logging (MRIL) or High-Resolution Array Induction (HRAI)logging systems.

Fluid extraction tool 150 can be conveyed into the wellbore 140 byconveyance 130 (as shown in FIG. 1), which contains conductors forcarrying power to the various components of the tool and conductors orcables (coaxial or fiber optic cables) for providing two-way datacommunication between the fluid extraction tool 150 and the loggingfacility 170 (as shown in FIG. 1). The logging facility 170, asdescribed above, preferably comprises a computer and associated memoryfor storing programs and data. The logging facility 170 generallycontrols the operation of fluid extraction tool 150 and process datareceived during operations. The logging facility 170 can include, but isnot limited to, a variety of associated peripherals, such as a recorderfor recording data, a display for displaying desired information, and aprinter. In a specific embodiment, telemetry module 70 may provide bothelectrical and data communications between the modules and the loggingfacility 170 (as shown in FIG. 1). In particular, telemetry module 70provides high-speed data bus from the control unit to the modules todownload sensor readings and upload control instructions initiating orending various test cycles and adjusting different parameters, such asthe rates at which various pumps are operating.

The injection device 10 and/or formation tester 30 may inject a SPA fromthe sampling tool 150 into the area of the wellbore and formation wheremobility testing or sampling is desired. The SPA can be injected intothe earth formation in the vicinity of the formation tester 30, prior tothe extraction of any formation fluid. The amount of SPA necessary forfluid extraction may be low and therefore may not require mixing withthe drilling fluid. Therefore the injection of the SPA can be focused onthe sample area. Alternatively, the SPA can be dispersed in the drillingmud. As known in the art, formation fluid sampling can be conductedwhile drilling. For efficient sampling while drilling, the injection ofthe material can occur before collection of the samples, or, in thealternative, the sampling can occur after a predetermined period oftime, allowing time for the material to absorb water, crosslink, andsegregate fluid phases within the rock prior to extraction.Additionally, the material can be injected during the drillingoperations as samples are being collected.

During wireline operations, the injection and analysis can occur duringthe same logging pass or a different logging pass. For example, theinjection can be made and the sample collected while the tool isstationary, or, in the alternative the injection can be performed duringthe down-logging pass and the sampling and testing can be conductedduring the up-logging pass, allowing the permeability modifier time todisperse and crosslink to the water molecules.

The flow control module 40 of the fluid extraction tool 150 can includea double acting piston pump 42, which can control the formation fluidflow from the earth formation drawn into probes 32A and 32B. Formationfluid which is drawn in via probes 32A and 32B maybe be taken into line15 for mobility testing within fluid testing section 50 and/or providedto sample collection module 60. The extracted fluid can be referred toherein as a fluid sample whether used for fluid mobility testing orcollection in sample collection module 60. The pump 42 is reversiblesuch that in addition to drawing fluid from the formation, it can alsobe used to inject SPA from probes 32A and 32B or injection device 10into the formation. Alternatively multiple pumps may be used, forexample one pump may be employed for drawing in fluid on the one handand separate second pump provided for injecting the SPA on the other.The pump operation can be monitored by the logging facility 170.

Fluid entering the probes 32A and 32B flows through flow line 15 and canalso be discharged into the wellbore 140 via outlet 44. A fluid controldevice, such as a control valve, can be connected to flow line 15 tocontrol the expulsion of discharged fluid from the flow line 15. Flowcontrol module 40 may additionally include one or more flow rate sensorsand/or pressure sensors such as strain-gauge pressure transducers thatcan measure flow rate and/or inlet and outlet pump pressures.

In order to test the mobility of the fluid drawn from the formation, thefluid testing section 50 of the tool can include a fluid testing device,which can analyze the fluid flowing through flow line 15. For thepurpose of this example, any suitable device or devices can be utilizedto analyze the fluid mobility of the formation. In the case at hand, dueto the injection of a SPA into the formation, the flow of water in theformation should be prevented or reduced, while on the other hand, theflow of hydrocarbon is respectively enhanced. Accordingly, the mobilityof the hydrocarbon phase is fluid which is tested as disclosed herein.These devices for determining fluid mobility may include, but are notlimited to, pressure transducers such as quartz pressure crystalpressure transducer, such as a Quartzdyne® pressure gauge. For exampleHalliburton's Single Gauge quartz Pressure tool (QPS) maybe employed.Additionally, devices may be employed which include a number of sensorsor quartz gauges. For example, in such gauge carriers the pressureresonator, temperature compensation, and reference crystal are packagedas a single unit with each adjacent crystal in direct contact. Theassembly can be contained in an oil bath that is hydraulically coupledwith the pressure being measured. The quartz gauge enables the device toobtain a measurement of parameters such as the drawdown pressure offluid being withdrawn from the earth formation and the fluidtemperature. In at least one instance, two fluid testing devices 52 canbe run in tandem to obtain the pressure difference between and determinethe viscosity of the fluid while pumping is in process or the density ofthe fluid once flow is stopped. Flow rate sensors can also be employedto determine the flow rate of the fluid being extracted to determinemobility of hydrocarbon in the formation. Both flow rate sensors andpressure sensors can both be employed.

Sample collection module 60 of the tool may contain chambers of varioussizes for storage of the collected fluid sample. Chamber section 60 caninclude at least one collection tube 62 and can additionally include apiston that divides collection tube 62 into a top chamber 62A and abottom chamber 62B. A conduit can be coupled with bottom chamber 62B toprovide fluid communication between bottom chamber 62B and the outsideenvironment, such as the inner surface of the wellbore. Additionally, afluid flow control device, such as an electrically controlled valve, canbe placed in the conduit to selectively open and close the valve toallow fluid communication between the bottom chamber 62B and thewellbore. Similarly, chamber section 60 may also contain a fluid flowcontrol device, such as an electrically operated control valve, which isselectively opened and closed to direct the formation fluid from theflow line 15 into the upper chamber 62A.

Formation tester 30, specifically probe 32, can have electrical andmechanical components that can facilitate testing, sampling, andextraction of fluids from the earth formation. The probe 32 can belaterally extendable by one or more actuators inside the formationtester 30 to extend the probe 32 away from the tool. Formation tester 30can retrieve and sample formation fluids throughout an earth formationalong the longitudinal axis of the wellbore. In accordance with thedisclosure an extendable probe 32 is provided coupled with at least onesealing pad providing a sealing contact with the inside surface of thewellbore at a desired location. Probe 32 can additionally include one ormore high-resolution temperature compensated strain gauge pressuretransducers (not shown), that can be isolated with shut-in valves tomonitor probe pressure. Fluids from the sealed-off part of the earthformation may be collected through one or more slits, fluid flowchannels, openings, outlets or recesses in the sealing pad. As discussedfurther with respect to FIG. 3B, the recesses, in the pad can beelongated along the axis of the pad. In at least one embodiment, theformation tester 30 is as further illustrated in FIGS. 3A and 3B. WhileFIG. 3A illustrates a formation tester 30 with a single probe, it wouldbe understood by those in the art that any number of probes may be usedwithout diverging from the scope of this description.

FIG. 3A illustrates a portion of the fluid extraction tool 150,including the injection device 10 and the formation tester 30. FIG. 3Ashows extendable supports 31A, 31B located opposite the probe 32 of theformation tester 30. Extendable supports 31A, 31B are laterally movableby actuators placed inside the formation tester 30 to extend away fromthe tool. While FIG. 3A illustrates a formation tester 30 with twoextendable supports, it would be understood by those in the art that anynumber of extendable supports may be used without diverging from thescope of this description. Additionally, while FIG. 3A shows that theextendable supports that extend in the opposite direction of the probe32, it would be understood by those of skill in the art that thesupports could extend in any direction.

The pump 33 can be used to perform analysis on a small volume sample offormation fluid. The pump 33 can be, but is not limited to, a pistonpump. Pump 33 can have a high-resolution, strain-gauge pressuretransducer, similar to that described with respect to the probe, whichcan be isolated from the intra-tool flow line 15 and probe 32.Additionally, the module may include a resistance, optical, or othertype of cell (not shown) located near probe 32 which can monitor fluidproperties as fluid enters the probe 32.

The pump 33 can also be used to inject selectively permeable agentthrough an outlet in probe 32 into the formation. A chamber 12 can beprovided for holding a SPA. For example, the SPA can be drawn from thechamber 12 and injected through the probe 32 into the formation.Alternatively, pump 42 (as shown in FIG. 2) or other pumps may beemployed for injecting the selectively permeable agent through probe 32.The SPA injected into the annulus or formation via an outlet or otheropening in the probe 32. The opening through which fluid is extractedmay also serve as an outlet through which selectively permeable agent isinjected (or expelled) to the formation.

As shown in FIG. 3A, and illustrated in further detail in FIG. 3B, asealing pad 34 can be coupled with the probe 32 and is capable ofsealing off a portion of the wellbore. Sealing pad 34 can be permanentlycoupled or removably attached to the probe 32. FIG. 3B illustrates afront view of the sealing pad 34 and the recess 36. Although notillustrated, one of skill in the art would understand that an array ofsealing pads 34 may be used with different angular deployment withrespect to the wellbore (for example, diagonally opposite, or placed atvarious angles with respect to the probe).

In alternative embodiments, design flexibility can be provided usingredundancy schemes, in which sealing pads of various sizes andproperties can be attached to any number of extension elements orprobes, and can use various combinations of screens, filtering packs,and any other suitable filtering means. As described above, alternativedesigns can be used interchangeably with the specific designsillustrated in this disclosure.

As noted previously, the probes 32A and 32B may be employed forinjecting SPA into the formation. Alternatively, a separate injectiondevice 10 may be employed. Referring back to FIG. 3A, an injectiondevice 10 is shown coupled with the formation tester 30. The injectiondevice 10 can include a chamber 12B for holding a SPA, a pump 14, afluid flow line 16, and an outlet 18. The outlet 18 serves as an openingthrough which the SPA is pumped and injected into the earth formation.

The SPA is any agent which selectively modifies the permeability ofcertain fluids, and in the illustrative instance, blocks or reduces theflow of water while permitting or enhancing the flow of formationhydrocarbons. For purposes of the present disclosure, SPA may include,but are not limited to, relative permeability modifiers (RPM)disproportionate permeability reducers (DPR), or formation fluidmobility modifiers (FFMM), and the like. For example, such materials canimprove the fluid extraction process in a variety of ways including, butnot limited to, segregate flow pathways between oil and water, shrinkwhen in contact with oil and swell when in contact with water, andabsorb in the pore walls of the earth formation.

Additionally, the fluid extraction tool 150 along with the SPA describedherein can also be used for: (1) improving efficiency and effectivenessin formation testing, (2) collecting high-quality hydrocarbon liquidsamples and reducing pump time in multiphase system, (3) assessingformation matrix mobility from fracture mobility in fracturedformations, or (4) obtaining near-single phase hydrocarbon mobility andeffective permeability in reservoir depths were high water contaminationsamples are produced. When the material is injected into the wellbore,the injection pressure can be, but does not have to be, higher than theextraction pressure.

SPAs can include polymers and gels which swell in the presence of water.The SPA may include super absorbent polymer gel which may becrosslinkable. The expansion has the effect of reducing the availablecross-sectional flow area for the fluid flow channel, which selectivelyincreases resistance to a particular fluid such as water flow.

Suitable RPMs known in the art may be employed, and which may include ahydrophilic polymer, for example cationic or anionic, or zwitterionicpolymers. Particular exemplary relative permeability modifiers includepolyacrylamides, such as partially hydrolyzable polyacrylamides, andcopolymers of polyacrylamides with acids such as acrylic acid. Thesepolymers may also be cross-linkable. Cross-linking agents may also beprovided, such as compounds or complexes which provide multivalent, andat least trivalent metal ions. For example, cross-linking agents mayinclude compounds or complexes having metals, transition metals,post-transition metals, and in particular having aluminum, chromium,zirconium, as well ions of the aforementioned, and mixtures thereof.Relative permeability modifiers may be used in conjunction with asubstrate. In one application, the polymer may be bonded to individualparticles of a substrate. Example substrate materials include sand,gravel, metal balls, ceramic particles, and inorganic particles,nano-particles of the aforementioned, or any other material that isstable in a down-hole environment. Materials that may function asrelative permeability modifiers are described in for example U.S. Pat.Nos. 6,474,413, 7,084,094, 7,159,656, and 7,395,858. An exemplarymodifier may be the chemical formula employed by WaterWeb® service byHalliburton Energy Services, Inc. An exemplary FFMM may include OilPerm™FFMM by Halliburton Energy Services, Inc.

The sampling tool 150 and any of its devices or modules may include oneor more suitable computer, controller, or processors capable of beingprogrammed to carry out the method, system, and apparatus as furtherdescribed herein. This includes the operation of any pumps, theextraction of fluids from the formation and/or injection of SPAs, ordirection of fluid within the devices and lines within the sampling tool150. FIGS. 4A and 4B illustrate exemplary computing units and/orprocessors which can be employed to practice the concepts, methods, andtechniques disclosed herein. The more appropriate embodiment will beapparent to those of ordinary skill in the art when practicing thepresent technology. Persons of ordinary skill in the art will alsoreadily appreciate that other system embodiments are possible.

FIG. 4A illustrates a conventional system bus computing systemarchitecture 400 wherein the components of the system are in electricalcommunication with each other using a bus 405. System 400 can include aprocessing unit (CPU or processor) 410 and a system bus 405 that couplesvarious system components including the system memory 415, such as readonly memory (ROM) 420 and random access memory (RAM) 435, to theprocessor 410. The system 400 can include a cache of high-speed memoryconnected directly with, in close proximity to, or integrated as part ofthe processor 410. The system 400 can copy data from the memory 415and/or the storage device 430 to the cache 412 for quick access by theprocessor 410. In this way, the cache 412 can provide a performanceboost that avoids processor 410 delays while waiting for data. These andother modules can control or be configured to control the processor 410to perform various actions. Other system memory 415 may be available foruse as well. The memory 415 can include multiple different types ofmemory with different performance characteristics. It can be appreciatedthat the disclosure may operate on a computing device 400 with more thanone processor 410 or on a group or cluster of computing devicesnetworked together to provide greater processing capability. Theprocessor 410 can include any general purpose processor and a hardwaremodule or software module, such as first module 432, second module 434,and third module 436 stored in storage device 430, configured to controlthe processor 410 as well as a special-purpose processor where softwareinstructions are incorporated into the actual processor design. Theprocessor 410 may essentially be a completely self-contained computingsystem, containing multiple cores or processors, a bus, memorycontroller, cache, etc. A multi-core processor may be symmetric orasymmetric.

The system bus 405 may be any of several types of bus structuresincluding a memory bus or a memory controller, a peripheral bus, and alocal bus using any of a variety of bus architectures. A basicinput/output (BIOS) stored in ROM 420 or the like, may provide the basicroutine that helps to transfer information between elements within thecomputing device 400, such as during start-up. The computing device 400further includes storage devices 430 or computer-readable storage mediasuch as a hard disk drive, a magnetic disk drive, an optical disk drive,tape drive, solid-state drive, RAM drive, removable storage device, aredundant array of inexpensive disks (RAID), hybrid storage device, orthe like. The storage device 430 can include software modules 432, 434,436 for controlling the processor 410. The system 400 can include otherhardware or software modules. The storage device 430 is connected to thesystem bus 405 by a drive interface. The drives and the associatedcomputer-readable storage devices provide non-volatile storage ofcomputer-readable instructions, data structures, program modules andother data for the computing device 400. In one aspect, a hardwaremodule that performs a particular function includes the softwarecomponents shorted in the tangible computer-readable storage device inconnection with the necessary hardware components, such as the processor410, bus 405, and so forth, to carry out a particular function. In thealternative, the system can use a processor and computer-readablestorage device to store instructions which, when executed by theprocessor, cause the processor to perform operations, a method, or otherspecific actions. The basic components and appropriate variations can bemodified depending on the type of device, such as whether the device 400is a small, handheld computing device, a desktop computer, or a computerserver. When the processor 410 executes instructions to perform“operations”, the processor 410 can perform the operations directlyand/or facilitate, direct, or cooperate with another device or componentto perform the operations.

To enable user interaction with the computing device 400, an inputdevice 445 can represent any number of input mechanisms, such as amicrophone for speech, a touch-sensitive screen for gesture or graphicalinput, keyboard, mouse, motion input, speech and so forth. An outputdevice 442 can also be one or more of a number of output mechanismsknown to those of skill in the art. In some instances, multimodalsystems can enable a user to provide multiple types of input tocommunicate with the computing device 400. The communications interface440 can generally govern and manage the user input and system output.There is no restriction on operating on any particular hardwarearrangement and therefore the basic features here may easily besubstituted for improved hardware or firmware arrangements as they aredeveloped.

Storage device 430 is a non-volatile memory and can be a hard disk orother types of computer readable media which can store data that areaccessible by a computer, such as magnetic cassettes, flash memorycards, solid state memory devices, digital versatile disks (DVDs),cartridges, RAMs 425, ROM 420, a cable containing a bit stream, andhybrids thereof.

The logical operations for carrying out the disclosure herein mayinclude: (1) a sequence of computer implemented steps, operations, orprocedures running on a programmable circuit with a general usecomputer, (2) a sequence of computer implemented steps, operations, orprocedures running on a specific-use programmable circuit; and/or (3)interconnected machine modules or program engines within theprogrammable circuits. The system 400 shown in FIG. 4A can practice allor part of the recited methods, can be a part of the recited systems,and/or can operate according to instructions in the recited tangiblecomputer-readable storage devices.

One or more parts of the example computing device 400, up to andincluding the entire computing device 400, can be virtualized. Forexample, a virtual processor can be a software object that executesaccording to a particular instruction set, even when a physicalprocessor of the same type as the virtual processor is unavailable. Avirtualization layer or a virtual “host” can enable virtualizedcomponents of one or more different computing devices or device types bytranslating virtualized operations to actual operations. Ultimatelyhowever, virtualized hardware of every type is implemented or executedby some underlying physical hardware. Thus, a virtualization computelayer can operate on top of a physical compute layer. The virtualizationcompute layer can include on or more of a virtual machine, an overlaynetwork, a hypervisor, virtual switching, and any other virtualizationapplication.

The processor 410 can include all types of processors disclosed herein,including a virtual processor. However, when referring to a virtualprocessor, the processor 410 includes the software components associatedwith executing the virtual processor in a virtualization layer andunderlying hardware necessary to execute the virtualization layer. Thesystem 400 can include a physical or virtual processor 410 that receivesinstructions stored in a computer-readable storage device, which causesthe processor 410 to perform certain operations. When referring to avirtual processor 410, the system also includes the underlying physicalhardware executing the virtual processor 410.

FIG. 4B illustrates an example computer system 450 having a chipsetarchitecture that can be used in executing the described method andgenerating and displaying a graphical user interface (GUI). Computersystem 450 can be computer hardware, software, and firmware that can beused to implement the disclosed technology. System 450 can include aprocessor 455, representative of any number of physically and/orlogically distinct resources capable of executing software, firmware,and hardware configured to perform identified computations. Processor455 can communicate with a chipset 460 that can control input to andoutput from processor 455. Chipset 460 can output information to outputdevice 465, such as a display, and can read and write information tostorage device 470, which can include magnetic media, and solid statemedia. Chipset 460 can also read data from and write data to RAM 475. Abridge 480 for interfacing with a variety of user interface components485 can include a keyboard, a microphone, touch detection and processingcircuitry, and pointing device, such as a mouse, and so on. In general,inputs to system 450 can come from any of a variety of sources, machinegenerated and/or human generated.

Chipset 460 can also interface with one or more communication interfaces490 that can have different physical interfaces. Such communicationinterfaces can include interfaces for wired and wireless local areanetworks, for broadband wireless networks, as well as personal areanetworks. Some applications of the methods for generating, displaying,and using the GUI disclosed herein can include receiving ordereddatasets over the physical interface or be generated by the machineitself by processor 455 analyzing data stored in storage 470 or RAM 475.Further, the machine can receive inputs from a user via user interfacecomponents 485 and execute appropriate functions, such as browsingfunctions by interpreting these inputs using processor 455.

It can be appreciated that systems 400 and 450 can have more than oneprocessor 410, 455 or be part of a group or cluster of computing devicesnetworked together to provide processing capability. For example, theprocessor 410, 455 can include multiple processors, such as a systemhaving multiple, physically separate processors in different sockets, ora system having multiple processor cores on a single physical chip.Similarly, the processor 410 can include multiple distributed processorslocated in multiple separate computing devices, but working togethersuch as via a communications network. Multiple processors or processorcores can share resources such as memory 415 or the cache 412, or canoperate using independent resources. The processor 410 can include oneor more of a state machine, an application specific integrated circuit(ASIC), or a programmable gate array (PGA) including a field PGA.

Methods according to the aforementioned description can be implementedusing computer-executable instructions that are stored or otherwiseavailable from computer readable media. Such instructions can compriseinstructions and data which cause or otherwise configured a generalpurpose computer, special purpose computer, or special purposeprocessing device to perform a certain function or group of functions.Portions of computer resources used can be accessible over a network.The computer executable instructions may be binaries, intermediateformat instructions such as assembly language, firmware, or source code.Computer-readable media that may be used to store instructions,information used, and/or information created during methods according tothe aforementioned description include magnetic or optical disks, flashmemory, USB devices provided with non-volatile memory, networked storagedevices, and so on.

For clarity of explanation, in some instances the present technology maybe presented as including individual functional blocks includingfunctional blocks comprising devices, device components, steps orroutines in a method embodied in software, or combinations of hardwareand software. The functions these blocks represent may be providedthrough the use of either shared or dedicated hardware, including, butnot limited to, hardware capable of executing software and hardware,such as a processor 410, that is purpose-built to operate as anequivalent to software executing on a general purpose processor. Forexample, the functions of one or more processors represented in FIG. 4Amay be provided by a single shared processor or multiple processors (useof the term “processor” should not be construed to refer exclusively tohardware capable of executing software). Illustrative embodiments mayinclude microprocessor and/or digital signal processor (DSP) hardware,ROM 420 for storing software performing the operations described below,and RAM 435 for storing results. Very large scale integration (VLSI)hardware embodiments, as well as custom VLSI circuitry in combinationwith a general purpose DSP circuit, may also be provided.

The computer-readable storage devices, mediums, and memories can includea cable or wireless signal containing a bit stream and the like.However, when mentioned, non-transitory computer-readable storage mediaexpressly exclude media such as energy, carrier signals, electromagneticwaves, and signals per se.

Devices implementing methods according to these disclosures can comprisehardware, firmware and/or software, and can take any of a variety ofform factors. Such form factors can include laptops, smart phones, smallform factor personal computers, personal digital assistants, rackmountdevices, standalone devices, and so on. Functionality described hereinalso can be embodied in peripherals or add-in cards. Such functionalitycan also be implemented on a circuit board among different chips ordifferent processes executing in the single device.

The instructions, media for conveying such instructions, computingresources for executing them, and other structures for supporting suchcomputing resources are means for providing the functions described inthe present disclosure.

FIG. 5 illustrates a method 500 for selecting a SPA to be used duringproduction based on the specific characteristics of the formation fluidpresent in the wellbore. At block 510, a fluid extraction tool isprovided, the fluid extraction tool can have a plurality of modules,including an injection device capable of injecting a material into theannulus of the wellbore. At block 520, the fluid extraction tool islowered into the wellbore to a predetermined depth, at which testing isdesired. At block 530, a SPA is injected into the area to be tested inthe wellbore. The SPA may be those described in detail above. The SPAmay be held in a chamber and may be injected in a variety of forms,including, but not limited to, viscose polymer solutions, powders,nano-particles, and gels. If a polymer or polymer gel is used, thematerial can be, but is not limited to, a powder, a solution, or anemulsifier. The powder form of a polymer, or polymer gel, can allow fordispersion into the formation, and the absorption of water will notoccur until after the powder is inside the earth formation. One exampleof a useful material is dried, cross-linked polyacrylamide powders(PPG), which is a super absorbent polymer capable of absorbing over onehundred times the weight of the powder in liquids and does not easilyrelease fluid under pressure. In the alternative, polymer-coatednano-particles can be used as a displacing agent. The nano-particle sizecan be adjusted to obtain the desired water-permeability effect. Inaddition to a relative permeability modifier, the SPA can also include atrigger mechanism, such as a pH-based activator. The pH-based activatorcan be used to activate the relative permeability modifier when thematerial reaches the earth formation. At block 540, the material isallowed to disperse throughout the section of the wellbore that is beingtested.

At block 550, one or more extendible supports and one or more extendablesealing pads are extended out from the body of the fluid extractiontool. The extendable appendages can stabilize the tool by pressingagainst the inner surface of the wellbore such that the sealing padseals off the section of the earth formation to be tested. At block 560,a pump within the formation tester extracts a sample of formation fluidfrom the earth formation and draws the sample into the recess within thesealing pad. Initially, the extracted sample may contain a large amountof permeability modifier, as well as water-based mud filtrate. Thecontaminated portion of the sample can be discarded through an outletport in the formation tester. As fluid is continually extracted from theearth formation, the sample will become less contaminated. Ahigh-resolution stain-gauge can be included near the entrance to thefluid flow tube allowing for a quick initial analysis of the material todetermine if contamination is present. If contamination continues,various components can be used to separate the permeability modifiercontamination from the formation fluid sample. For example, a polymercoated magnetic nano-particle can be placed in the dispersed material, adensity disparity can allow for gravitational segregation, or acentrifuge may be used to separate the sample. In the alternative, somepermeability modifiers can block filtrate flow, allowing for a clean oilsample to be collected from the start. At block 570, the clean formationfluid sample is collected in one or more sample tubes within the tool.

At block 580 the mobility of the hydrocarbon phase in the formation canbe determined. The analysis can be done by a sensor housed within theformation tester as the fluid is drawn from the formation through theextendable sealing pads according to block 560 or sensor within thefluid test module, as described above. The sensor can conduct a mobilityassessment on fluids taken, for the purposes of this example, fromnon-fractured reservoirs.

The fluid mobility of a multi-fluid scenario is not very informative ofa hydrocarbon portion or phase. Accordingly, as disclosed herein by useof the SPAs, the determination of the mobility of hydrocarbons withinthe formation can be isolated to some degree. This can be shown in thefollowing. Total mobility for a three-phase flow system can bedetermined by Equation 1.

$\begin{matrix}{\lambda_{t} = {\frac{k_{oil}}{\mu_{oil}} + \frac{k_{gas}}{\mu_{gas}} + \frac{k_{water}}{\mu_{water}}}} & (1)\end{matrix}$In the alternative, where gas is a minor (or negligible) factor, it canbe removed from the equation. In such cases, the total mobility of anoil-water two-phase flow scenario can be defined by Equation 2.

$\begin{matrix}{\lambda_{t} = {\frac{k_{oil}}{\mu_{oil}} + \frac{k_{water}}{\mu_{water}}}} & (2)\end{matrix}$The use of a relative permeability modifier, such as those describedabove, in the extraction process can suppress the mobility of water,without negatively affecting oil mobility. Thus, when a permeabilitymodifier is used during extraction, the liquid hydrocarbon phasemobility can be approximated by Equation 3.

$\begin{matrix}{\left. \lambda_{t}\rightarrow\lambda_{oil} \right. = \frac{k_{oil}}{\mu_{oil}}} & (3)\end{matrix}$

In some cases where the gas phase is primarily hydrocarbon, then boththe liquid and gas phases of the hydrocarbon phase can be determined.

The above method can be used for a variety of purposes, includingimproving the quality of formation fluid samples collected anddetermination of mobility of the hydrocarbon phase in the formation. Atblock 590, a preferred permeability modifier is selected based on theproperties of the formation fluid present. The injection of apermeability modifier into wellbore formations, such as transitionzones, high water-cut reservoirs, and fracture reservoirs allows for theextraction of a less contaminated sample.

In an alternative example, a mobility assessment as described above canbe conducted in a naturally fractured reservoir. For example, the poresystems of fractured reservoir rocks can be treated as a dual-porosity,or dual-permeability, system. The fractures can be viewed as fissurepores and the remaining porosity consists of matrix pores. For naturallyfractured reservoir rocks, the measure of total mobility of a fluidsample is dominated by the mobility of the fractures, especially if thefractures are well connected. The permeability of the rock matrix issignificantly lower than that of the fractures, thus the mobility of thehydrocarbons stored in matrix pores may not be assessed correctly in thetotal mobility calculation. However, a permeability modifier injectionprior to mobility testing can significantly impede the flow in thefractures. For example, an RPM such as a super water-absorbent polymergel can effectively crosslink within the fractures to hinder flowcausing the dual-porosity system to act like a single porosity system.Specifically, the permeability modifier can form an internal cake alongthe fractures, blocking fluid flow and allowing formation drawdownpressure measurements to yield a hydrocarbon phase mobility extremelysimilar to the true matrix mobility.

In the alternative, the method can be used in mature wellbores. Maturewellbores are typically unable to produce hydrocarbons in quantitiesallowing for profit, and are thus left as residual oil saturation withinthe earth formation. Injecting a permeability modifier into theformation can allow for hydrocarbon-heavy samples to be extracted inareas where they were previously unattainable.

In sampling a mature reservoir, designing a successful permeabilitymodifier flooding program is critical to the ultimate production andenhanced oil recovery (EOR). Typically, numerical simulations, orlaboratory core flooding experiments, are used in order to predict theoutcome and in selecting the permeability formula. An in-situ fieldpilot program using an injection and production well is significantlymore costly and time consuming. Using the method described in FIG. 5, asmall scale, in-situ test can be performed in a shorter period of time,and can provide the initial EOR oil production data in actual reservoirconditions. Such data once obtained can be fed into a reservoirsimulator to help designing the EOR strategy.

Numerous examples are provided herein to enhance understanding of thepresent disclosure. A specific set of statements are provided asfollows.

Statement 1: A method for obtaining formation fluid samples, the methodcomprising disposing a fluid extraction tool into a wellbore extendingthrough a subterranean earth formation; injecting, from the fluidextraction tool, a selective permeability agent into the wellbore at apredetermined depth; and extracting, from the earth formation, a sampleof a formation fluid.

Statement 2: A method according to Statement 1, wherein extracting thesample of the formation fluid comprises extending a sealing pad from aportion of a body of the fluid extraction tool, the sealing pad havingat least one opening for establishing fluidic communication between theearth formation and the interior of the body, the sealing pad having anouter surface to hydraulically seal a region along an inner surface ofthe wellbore and at least one recess within the outer surface of thesealing pad, the at least one recess establishing a fluid flow channelalong the inner surface of the wellbore sealed off by the sealing pad,and extracting the formation fluid from the subterranean earth formationthrough the at least one opening.

Statement 3: A method according to Statement 1 or Statement 2, whereininjecting comprises injecting the selective permeability agent throughthe at least one opening of the sealing pad which serves as an outlet.

Statement 4: A method according to Statements 1-3, wherein injectingcomprises injecting the selective permeability agent into thesubterranean earth formation from an opening other than the at least oneopening of the sealing pad.

Statement 5: A method according to Statements 1-4, further comprisingcontaining the selective permeability agent in a chamber disposed withinthe extraction tool.

Statement 6: A method according to Statements 1-5, further comprisingtesting the formation fluid mobility via a formation fluid mobilitytesting sensor.

Statement 7: A method according to Statements 1-6, further comprisingtesting the mobility of the formation fluid being extracted.

Statement 8: A method according to Statements 1-7, further comprisingholding the extracted formation fluid in a sample collection chamber.

Statement 9: A method according to Statements 1-8, further comprisingselecting the selective permeability agent from the group consisting ofa disproportionate permeability reducer, a relative permeabilitymodifier, a formation fluid mobility modifier, and mixtures thereof.

Statement 10: A method according to Statements 1-9, further comprisingselecting the selective permeability agent comprising polyacrylamide.

Statement 11: A system comprising a fluid extraction tool disposed in awellbore comprising a body; a sealing pad extending from a portion ofthe body, the sealing pad having at least one opening for establishingfluidic communication between an earth formation and the interior of thebody, the sealing pad having an outer surface to hydraulically seal aregion along an inner surface of a wellbore and at least one recesswithin the outer surface of the sealing pad, the at least one recessestablishing a fluid flow channel along the inner surface of thewellbore sealed off by the sealing pad; a container holding a selectivepermeability agent; a processor communicatively coupled with the fluidextraction tool, the processor comprising a memory storing instructionsthat, when executed by the processor, cause the processor to performoperations comprising pumping, from the fluid extraction tool, theselective permeability agent into the wellbore at a predetermined depth,extracting, from the earth formation, a sample of a formation fluid.

Statement 12: A system according to Statement 11, wherein the memorystoring further instructions that, when executed by the processor, causethe processor to perform operations further comprising analyzing, at asensor, a formation fluid mobility for the formation.

Statement 13: A system according to Statement 11 or Statement 12,further comprising a display communicatively coupled with the processorand rendering the analysis.

Statement 14: A system according to Statements 11-13, wherein theselective permeability agent is selected from the group consisting of adisproportionate permeability reducer, a relative permeability modifier,a formation fluid mobility modifier, and mixtures thereof.

Statement 15: A system according to Statements 11-14, wherein theselective permeability agent comprises polyacrylamide.

Statement 16: A fluid extraction tool comprising a body; a sealing padextending from a portion of the body, the sealing pad having at leastone opening for establishing fluidic communication between an earthformation and the interior of the body, the sealing pad having an outersurface to hydraulically seal a region along an inner surface of awellbore and at least one recess within the outer surface of the sealingpad, the at least one recess establishing a fluid flow channel along theinner surface of the wellbore sealed off by the sealing pad; a containerholding a selective permeability agent; one or more devices forinjecting the selective permeability agent through at least one outletof the body into the earth formation, and extracting a formation fluidthrough the at least one opening into the body, wherein the formationfluid being collected is from the region along the inner surface of thewellbore sealed off by the sealing pad.

Statement 17: A fluid extraction tool according to Statement 16, whereinthe one or more devices comprises one or more pumps.

Statement 18: A fluid extraction tool according to Statement 16 orStatement 17: wherein the at least one opening of the sealing pad servesas the at least one outlet of the body through which the selectivepermeability agent is injected into the earth formation.

Statement 19: A fluid extraction tool according to Statements 16-18,wherein the selective permeability agent is selected from the groupconsisting of a disproportionate permeability reducer, a relativepermeability modifier, a formation fluid mobility modifier, and mixturesthereof.

Statement 20: A fluid extraction tool according to Statements 16-19,wherein the selective permeability agent comprises polyacrylamide.

The embodiments shown and described above are only examples. Even thoughnumerous characteristics and advantages of the present technology havebeen set forth in the foregoing description, together with details ofthe structure and function of the present disclosure, the disclosure isillustrative only, and changes may be made in the detail, especially inmatters of shape, size and arrangement of the parts within theprinciples of the present disclosure to the full extent indicated by thebroad general meaning of the terms used in the attached claims. It willtherefore be appreciated that the embodiments described above may bemodified within the scope of the appended claims.

What is claimed is:
 1. A method for obtaining formation fluid samples,the method comprising: disposing a fluid extraction tool into a wellboreextending through a subterranean earth formation; injecting, from thefluid extraction tool, a selective permeability agent into thesubterranean earth formation at a sample area, wherein the selectivepermeability agent enhances a flow of a desired fluid and suppresses aflow of an undesired fluid; and extracting, from the sample area of thesubterranean earth formation, a sample of the desired fluid, wherein thedesired fluid is a formation fluid.
 2. The method of claim 1, whereinextracting the sample of the formation fluid comprises: extending asealing pad from a portion of a body of the fluid extraction tool, thesealing pad having at least one opening for establishing fluidiccommunication between the subterranean earth formation and an interiorof the body of the fluid extraction tool, the sealing pad having anouter surface to hydraulically seal the sample area along an innersurface of the wellbore and at least one recess within the outer surfaceof the sealing pad, the at least one recess establishing a fluid flowchannel along the inner surface of the wellbore sealed off by thesealing pad, and extracting the formation fluid from the sample area ofthe subterranean earth formation through the at least one opening. 3.The method of claim 2, wherein injecting comprises injecting theselective permeability agent through the at least one opening of thesealing pad which serves as an outlet.
 4. The method of claim 2, whereininjecting comprises injecting the selective permeability agent into thesubterranean earth formation from an opening other than the at least oneopening of the sealing pad.
 5. The method of claim 1, further comprisingcontaining the selective permeability agent in a chamber disposed withinthe fluid extraction tool.
 6. The method of claim 1, further comprisingtesting a mobility of the formation fluid via a formation tester.
 7. Themethod of claim 1, further comprising testing a mobility of theformation fluid being extracted.
 8. The method of claim 1, furthercomprising holding the extracted formation fluid in a sample collectionchamber.
 9. The method of claim 1, further comprising selecting theselective permeability agent, wherein the selective permeability agentincludes one or more of a disproportionate permeability reducer, arelative permeability modifier, a formation fluid mobility modifier, andmixtures thereof.
 10. The method of claim 1, further comprisingselecting the selective permeability agent based at least in part on thesubterranean earth formation of the wellbore, the selective permeabilityagent comprising polyacrylamide.
 11. The method of claim 1, wherein theundesired fluid is water.
 12. A system comprising: a fluid extractiontool disposed in a wellbore comprising: a body; a sealing pad extendingfrom a portion of the body, the sealing pad having at least one openingfor establishing fluidic communication between an earth formation and aninterior of the body, the sealing pad having an outer surface tohydraulically seal a sample area along an inner surface of the wellboreand at least one recess within the outer surface of the sealing pad, theat least one recess establishing a fluid flow channel along the innersurface of the wellbore sealed off by the sealing pad; and a containerholding a selective permeability agent that enhances a flow of a desiredfluid and suppresses a flow of an undesired fluid; a processorcommunicatively coupled with the fluid extraction tool, the processorcomprising: a memory storing instructions that, when executed by theprocessor, cause the processor to perform operations comprising:pumping, from the fluid extraction tool, the selective permeabilityagent into the earth formation at the sample area, and extracting, fromthe sample area of the earth formation, a sample of the desired fluid,wherein the desired fluid is a formation fluid.
 13. The system of claim12, wherein the memory storing instructions thereon further comprisesinstructions that, when executed by the processor, cause the processorto perform operations further comprising analyzing, via a formationtester, a formation fluid mobility for the formation.
 14. The system ofclaim 13, further comprising a display communicatively coupled with theprocessor and rendering the analysis.
 15. The system of claim 12,wherein the selective permeability agent includes one or more of adisproportionate permeability reducer, a relative permeability modifier,a formation fluid mobility modifier, and mixtures thereof.
 16. Thesystem of claim 12, wherein the selective permeability agent is selectedbased at least in part on the earth formation of the wellbore.
 17. Thesystem of claim 12, wherein the undesired fluid is water.
 18. A fluidextraction tool comprising: a body; a sealing pad extending from aportion of the body, the sealing pad having at least one opening forestablishing fluidic communication between an earth formation and aninterior of the body, the sealing pad having an outer surface tohydraulically seal a sample area along an inner surface of a wellboredescending through the earth formation and at least one recess withinthe outer surface of the sealing pad, the at least one recessestablishing a fluid flow channel along the inner surface of thewellbore sealed off by the sealing pad; a container holding a selectivepermeability agent that enhances a flow of a desired fluid andsuppresses a flow of an undesired fluid; and one or more devices forinjecting the selective permeability agent through at least one outletof the body into the sample area of the earth formation, and extractingthe desired fluid through the at least one opening into the body,wherein the desired fluid is a formation fluid from the region along theinner surface of the wellbore sealed off by the sealing pad.
 19. Thefluid extraction tool of claim 18, wherein the one or more devicescomprises one or more pumps.
 20. The fluid extraction tool of claim 18,wherein the at least one opening of the sealing pad serves as the atleast one outlet of the body through which the selective permeabilityagent is injected into the earth formation.
 21. The fluid extractiontool of claim 18, wherein the selective permeability agent includes oneor more of a disproportionate permeability reducer, a relativepermeability modifier, a formation fluid mobility modifier, and mixturesthereof.
 22. The fluid extraction tool of claim 18, wherein theselective permeability agent comprises polyacrylamide.
 23. The fluidextraction tool of claim 18, wherein the undesired fluid is water.